Prevention of ammonium sulfide corrosion



Patented Mar. 11, 1952 PREVENTION OF AMMONIUM SULFIDE CORROSIQN Christopher A. Murray, to The Pure Oil Com 1 poration of Ohio Neclerland, Tex., assignor pany, Chicago,-Ill., a cor- Application January 10, 1950, Serial No. 137,718

9' Claims.

This invention relates to corrosion inhibition and more particularly to the inhibition of corrosion of metal surfaces in oil refining equipment caused by the presence of sulfur-containing compounds and their complexes.

The corrosion of metal equipment due to contact with reagents and reactants has been a constant problem concerning the industries since the beginning of refining and treating processes. The development of processes involving extreme conditions, as, catalytic cracking, in whichvapors of heavy oil and steam are contacted at very high temperatures with a catalyst, has in many instances intensified the corrosion of metal equipment.

It is known that formaldehyde and various other oxygen-containing compounds will inhibit the corrosiveness of sulfur-containing compounds, especially hydrogen sulfide under certain conditions. One particularly efiective use of formaldehyde for this purpose has been in connection with hydrogen sulfide saturated brines. Aldehydes in general have been disclosed as inhibitors against the corrosion of refining equipment by the presence of hydrocarbons containing corrosive sulfides. In general, the inhibiting action of the formaldehyde has been attributed to its ability to form a protective coating on the surface of the metal, thereby preventing the contact of the corrosive agents with the metal. This ability of formaldehyde to form a protective coating functions especially well under conditions wherein the corrosive agents are contained in a liquid phase and the velocities of the liquid filow through the metal equipment are not high.

In certain types of refining operations like cracking, or removing gasoline hydrocarbons from gaseous hydrocarbon streams, wherein conditions of high temperature, high space velocities, and high pressures are encountered,v the inhibiting action of film-forming inhibitors is greatly decreased and their usefulness greatly reduced. In such operations .it has been. the practice to purify the reactants and hydrocarbons to remove the corrosive agents before any processing is attempted. However, there are limitations on these methods of purification which, whether because of cost or extent of sulfur contamination, or for other reasons, leave .much to be desired in the way of the elimination of costly corrosion of metal equipment. One such situation occurs when cracked oil vapors and steam are cooled and processed to obtain refinery gases, gasoline of high octane number, fuel oil and various recycle stocks. The products of the cracking operation contain various corrosive compounds including hydrogen sulfide, ammonia, and unidentified organic acidic compounds. Methods of dehydration and sulfide removal are costly and never percent efficient, and the last remainingsmall portions of these contaminants are the cause of very severe corrosion conditions. No methods heretofore known, have effectively reduced this type of corrosion.

The present invention is the result of an investigation of corrosion in Thermofor catalytic cracking units and gas plants associated therewith, and the discovery that formaldehyde and other lower molecular weight aldehydes are successful in oversoming the corrosiveness of products from and within these units as will later be explained in detail.

Accordingly, the foremost object of this invention is to provide a method for the inhibition of corrosion of metals due to the presence of systems containing hydrogen sulfide, ammonia and water.

Another object of this invention is the provision of a method of inhibiting the corrosiveness of ammonium sulfide hydrolysis products on metal by the use of low molecular weight aldehydes, especially formaldehyde.

Still another object of this invention is the prevention of corrosion of metals in refinery equipment due to the presence of ammonium hydrosulfide and water by the addition of small amounts of formaldehyde.

Other objects of this invention will become manifest from the following description and accompanying drawing of which the single figure isa diagrammatic elevational view of a gas plant for recovering and fractionating gas from an oil cracking unit.

In refining equipment including cracking units, fractionation units, distillation units, storage tanks and pipe lines, wherein liquid and/or gaseous .hydrocarbons containing sulfur compounds of a corrosive nature are processed or confined, there is often present ammonia and hydrogen sulfide and generally water along with the hy- 3 drocarbons. In some of these processes the ammonia may be injected as part of the procedure or may be produced during a previous process. For example, it is common-practice to inject ammonia into some process streams to eliminate mineral acid corrosion conditions in the various overhead streams passing through the equipment. In such systems the ammonia, being water soluble, reacts also with the hydrogen sulfide and water to form ammonium hydrosulfide or ammonium sulfide depending on the conditions present. Gas separation systems during purification procedures serve to remove the greater share of these corrosive compounds but during the final steps in the production of gasoline it is found that the last remaining traces of these materials offer an extremely corrosive atmosphere. Whether the ammonia is inherently present in the gas being processed or has been injected for the'purpose of eliminating acid corrosive conditions in the overhead streams, it serves to carry the corrosive sulfur compounds throughout the water phase and into the overhead streams. Formaldehyde injection, in accordance with this invention, serves to reduce the amount of corrosion due to the presence of these sulfur compounds in the overhead streams.

Support for this is found in my investigation of Thermofor catalytic cracking units, where ammonia is produced in the cracking operation, and of other processes involving injection of ammonia to alleviate corrosion, wherein, corrosion studies indicate that the ammonium sulfides or hydrosulfides attack not only the ferrous equipment but the non-ferrous as well. This corrosion is not severe as long as the water is present in vapor state. An investigation of gas recovery plants processing hydrocarbon gases, the gasoline fraction and steam from cracking units and tests for corrosives in the water and feed system of such units, indicate that ammonia, hydrogen sulfide, sulfur acids, ammonium sulfide and ammonium hydrosulfide are present throughout the system in the water phase. Liquid hydrocarbon streams within these units are relatively free from corrosives, the ammonia in system having extracted them to the water phase.

The corrosion is most severe further on in the system where the steam in the overhead streams is cooled to water and hydrolysis of the ammonium sulfides is promoted. For example, at the depentanizer and depropanizer reboilers, ammonium salts of sulfur acids dissociate or hydrolyze with water to give acidic conditions which have an extremely corrosive action on the reboiler tubes and necessitate their costly replacement at too frequent intervals. Corrosion is also severe in the coolers and heat exchangers. In those places in such systems where sludges or other residues provide a coalescing medium for water or produce galvanic effects, the corrosion is intensified. The presence of water in gas plants and ---other refining equipment is then the main cause of the corrosion because its presence is necessary to bring about the hydrolysis which yields the acidic corrosive products. It is next to impossible to eliminate water from such systems since it is present in the hydrocarbons being processed, both the gases and liquids, is introduced in the cracking phase, and enters wherever leaks occur or the system is not closed or is in contact with the air. The remaining possible solution is to inject or add an inhibitor to. the overhead streams or to the gases being 4 processed to reduce the attack of the metals, which is the purpose of this invention.

It has been found that by the addition of a low molecular weight aldehyde, preferably formaldehyde, the ammonium sulfide and hydrosulfide hydrolysis products are prevented from attacking the metal surfaces. One possible explanation is the formation of a non-corrosive product by the mechanism of the following reaction:

8H2CO+4(NH4) 2S v Thus, there is brought about a neutralization or inhibition of the corrosive ammonium sulfide. This reaction goes to completion and the formaldehyde-ammonium sulfide complex is not subject to hydrolysis. By the injection then of small amounts of a low molecular weight aldehyde into those places or streams within the refining equipment wherein excessive corrosion appears, the corrosion problem will be eliminated. The exact action of the formaldehyde in our process is not known. One apparently sound explanation of its function may be that the formaldehyde-ammonium sulfide complex itself forms a protective film over the metal surfaces. Formaldehyde is the only aldehyde which forms the ring complex with ammonium sulfides, however, other aldehydes should not be excluded from possible reaction with these sulfides since the functional group is the aldehyde group. In any event, the result is the tying up of the ammonium sulfides so that hydrolysis is prevented.

To more exactly explain the function of my invention, reference is made to the drawing which represents diagrammatically the process fiow of a gas plant for the removal of lower molecular weight hydrocarbons from the overhead products from a Thermofor catalytic cracking unit and the fractionation of said hydrocarbons. In the drawing, overhead products from a Thermofor catalytic cracking unit enter through line I and pass to gas separators 3 and 5 where as much of the water and heavier hydrocarbons are separated as is possible. The overhead will consist of an average composition somewhat as follows:

Moles/hour C1 and lighter 127.0 C2 unsaturates 18.2 C2 saturates 29.8 C3 unsaturates 60.6 C3 saturates 49.4 C4 iso 58.0 C4 unsaturates 72.0 0 normal 20.5 C5 saturates 100.0 Ca and heavier 3l5.9 H2O 96.5 H28 7.2 NH3 0.15

for a proposed operation of 10,000 bbls. of charging stock per operating day of the cracking unit. The gases leaving gas separators 3 and 5 via line i will consist of C1 to C3 hydrocarbons and a somewhat reduced portion of C4 to C6 hydrocarbons and about 64 moles per hour of water. Gas separators 3 and 5 operate at about to 120 F. with a preferred temperature of F. After compression to an initial pressure of 40140 p. s. i. these gases will have attained a temperature of about 265 F. This operation takes place in compressor 9. Minor portions of C1 to C5 hydrocarbons with the balance of the C6 and higher hydrocarbons pass from the bottom of gas separators 3 and 5 through lines II and I3 to pumps I5 and I1. All or part of the Ca hydrocarbons from pump I 1 may join the effluent from pump I 5 and pass through line 19 to coalescer 2|. And, depending on the degree of separation of pentane attained under the conditions of operation, all or part of the effluent from gas separator 3 passing through pump I5 may pass through line 23 and join the efiiuent from pump I1.

In coalescer 2|, the heavier hydrocarbons pass through a bed of especially prepared wood chips or sawdust which accumulates the water through water draw-off 25. The effluent hydrocarbons from coalescer 2| pass through line 21 and are mixed with a small quantity of formaldehyde flowing from proportionating pump 29 and formaldehyde storage tank 3i through line 33. The inhibited hydrocarbon mixture passes through heat exchanger and into the depentanizer 37 which is fitted with reboiler 39 and lines 4|, 43 and 45 for the purpose of distilling off the last pentane content of the gasoline. Depentanizer reboiler 30 is heated by steam passing through line 3?. Light ends of the motor gasoline being depentanized in depentanizer 37, that is, the C5 and lighter hydrocarbons, pass through depentanizer reflux accumulator 43 and line 49 back to the efiiuent side of compressor 9 for reprocessing in the absorber, depropanizer and debutanizer I stages of the plant, yet to be described. Depentanized gasoline is withdrawn through line 50.

The combined efiiuents from depentanizer 31 and gas separators 3 and 5 pass through line 5| and heat exchanger 53 into depropanizer charge-contacting accumulator 55 where the major portion of C1 and lighter gases with some C2 to C6 and water pass off through line 51, are compressed in compressor 59, and after passing through absorber charge cooler 60, the gases enter the bottom of absorber 6|. In absorber 5! the residue gases consisting mainly of C1 and C2 hydrocarbons are separated along with some of the water. Rich oil from absorber Bl passing through line 63, joins the condensate from accumulator 55 composed of Co and heavier hydrocarbons with smaller amounts of C1 to Css passing through line from accumulator 55. This combined stream flows into coalescer B! where again water is removed by sawdust. The efliuent from ccalescer 0? receives its injection of formaldehyde via line 59 from pump 29 and passes via line I0 through heat exchanger II and line I2 to depropanizer 13 where 03 and lighter hydrocarbons are removed. Depropanizer reflux accumulator M with accompanying condenser separates and returns any liquid hydrocarbons to the system. From depropanizer reboiler I5, functioning similar to reboiler 39, C and heavier hydrocarbons pass through line 11 and heat exchanger II via line 8| to debutanizer 83. Line and pump 81 serve as a draw-off for debutanizer 83, carrying the major portion of C5, C6 and heavier hydrocarbons back to absorber 6! to function as absorber oil. No more of the liquid hydrocarbons from separators 3 and 5 is passed. through line 5i than is sufficient to aid in the absorption of C1 and C2 hydrocarbons in absorber 6|.

With the process as so far described, provision has been made to treat the feed hydrocarbons going into depentanizer 3'I and depropanizer I3 with formaldehyde since it is in these pieces of apparatus and especially in reboilers 39 and i5 that corrosion is experienced. Provision may i also be made for a water coalescer and formal:

dehyde treatment of the feed passing through line 11 into debutanizer 83 to protect its reboiler. Formaldehyde may be caused to enter the system at any point whereby corrosive conditions exist. In some instances debutanized gasoline may be drawn oiT at line 89 without retreatment through absorber 6|.

In order to demonstrate the effectiveness of corrosion inhibition according to this invention the following examples are given:

Example 1.-A total of 851.4 moles per hour of a typical overhead from a gas separator of a crackling unit, containing C1 to C6 hydrocarbons, 96.5 mole per hour of water, 7.2 moles per hour of hydrogen sulfide and about 0.15 moles per hour of ammonia leaving the eiiiuent side of the gas separator pumps and passing to the depentanizer and depropanizer stages will require approximately 0.015 mole per hour of formaldehyde injected at the effluent from the coalescers to inhibit the corrosion during processing in a gas plant.

Example 2.--A sour crude containing 0.5% of sulfur compounds consisting of mercaptans, hydrosulfides, sulfides and disulfides along with 5.0% of water will require the addition of approximately 0.005% of ammonia and 0.005% of formaldehyde to inhibit the corrosiveness of the crude during storage. The ammonia and formaldehyde is added to the crude itself or may be injected into the vapor space of the storage vessel.

Example 3.Bottoms drain efiluent from an absorber intercooler of a gas plant shows an analysis of 0.143% ammonia, 0.336% hydrogen sulfide and a pH of 7.3. By injection of 0.145% of formaldehyde into the system the corrosion Within the intercooler is substantially inhibited.

Example 4.Water draw from a debutanizer q reflux accumulator of a gas plant shows an analysis 0.006% ammonia, 0.004% hydrogen sulfide and a pH of 8.8. The injection of 0.006% of formaldehyde into the intake line of the debutanizer effectively inhibits corrosion. at this point in the apparatus.

Example 5.--In a thermal cracking unit the overhead from the fractionating tower comprising C1 to C3 gaseous hydrocarbons and light naphtha and containing 0.05% by volume of. hy-

drogen sulfide is normally condensed. and the liquid hydrocarbons separated from the gaseous. The prior injection of 0.005% by volume of. am monia and 0.005% by volume of formaldehyde into this overhead substantially overcomes corrosion in the condensing and gas separation stages.

Example 6.A typical gas stream passing from coalescer 61 in the amount of 1333.? total moles per hour and having present 301.6 moles per hour of C1 to C3 hydrocarbons, 1032.1 moles per hour of C4 to C6 hydrocarbons and containing 9.8 moles per hour of hydrogen sulfide, 0.001 mole per hour of ammonia and 1.2 moles per hour of water will require the injection of approximately 0.001 mole per hour of formaldehyde to substantially overcome corrosion in the depropanizer reboiler I5.

From these examples it is seen that the amount of formaldehyde added is at least stoichiometrically equivalent to the amount of ammonia present. If the ammonia content is less than the hydrogen sulfide content, the minimum amount of formaldehyde used is an amount equivalent to the ammonia content. Where ammonia is injected into a system, the amount of ammonia 7 may be one-tenth that of the hydrogen sulfide present (mineral acidity having been neutralized) and the amount of formaldehyde be equivalent to the amount of ammonia.

Since ammonia, hydrogen sulfide and sulfur acids are distributed throughout the water phase, the gas separators, the absorber and the coalescers are employed to remove as much of the water as possible and thus reduce the amount of formaldehyde needed. The removal of all the water can not be accomplished, therefore, additional methods of inhibition, as proposed by this invention are imperative to prevent corrosion of the heated metal surfaces. We have found by an analysis of the water draw-01f effluents from the gas separators, feed and reflux accumulators and reboilers that the concentration of corrosives increases as the gases are compressed in successive stages through the plant. When the fluids or gases containing them are subjected to heating conditions, the ammonium sulfide and hydrosulfide compounds hydrolize to form the corrosive acids which attack the hot metal surfaces. The ammonium sulfide is entirely converted to ammonia and hydrogen sulfide at temperatures of 115 F. and above, while the thio acids form only at a much higher temperature, around 200 F. and above. The main source of corrosion seems to be the hydrogen sulfide and ammonia, and this invention is directed to inhibiting the attack of these compounds on metal surfaces.

The gas separators 3 and 5, for example, show a volume percent of water 8.80, the condensed water having an average pH of 8.5 with an ammonia content of 0.071 to 0.195 percent and a hydrogen sulfide content of 0.118 to 0.343 per cent. Analysis of the bottoms drain water from the depropanizer charge-contacting accumulator 55 shows a pH of 8.5, an ammonia content of 0.301 percent and a hydrogen sulfide content of 0.534 percent. On the same basis the depentanizer bottoms water having a pH of 6.3 displayed no ammonia and no hydrogen sulfide. However, analysis of the drain water effluent from the depentanizer reflux accumulator 38 shows a pH of 7.6, an ammonia content of 0.083 percent and a hydrogen sulfide content of 0.184 percent. The drain water from the debutanizer reflux accumulator 84 has a pH of 8.8 and an ammonia content of 0.006 with a hydrogen sulfide content of 0.004 in weight percent.

Both the tubes and shell of the depropanizer charge-bottoms exchanger ll carry liquid gaso line, water, ammonia, and hydrogen sulfide. Steel tubes used in this unit fail in about 9 months, the first pass section suffering the worst corrosion. Even Admiralty metal tubes only last 8 months before showing severe corrosion cracks on the shell sides of the tubes. New steel tubes of the depentanizer condenser, as another example, carrying cooling water and surrounded by hydrocarbon vapors, water vapors, hydrogen sulfide and ammonia, lasted only 11 months. Admiralty metal tubes in this unit lasted only 17 months. The debutanizer reboiler tubes carrying steam and surrounded by liquid gasoline, water and organic acid last at most seven months and then must be replaced because of corrosion. In all of these pieces of equipment there is water present in the liquid state.

The water phase of systems containing ammonia and hydrogen sulfide is generally alkaline since ammonia is more alkaline than hydrogen sulfide is acidic. The water draw-off points in the systems described contain ammonia and hy drogen sulfide in a more or less buffered solution in the form and ratio of ammonium hydrosulfide. The major portion of the ammonium hydrosulfide leaves the gas plant at the depropanizer overhead. Where 10,000 lb./day of hydrogen sulfide is produced in a Thermofor catalytic cracking unit only about lb./day of ammonia is produced and the water in the system carries about 200 lb./day of ammonium hydrosulfide. The major portion of this ammonium hydrosulfide is removed as liquid eflluent during the gas separation stages, the remainder stays in the gaseous phase. This explains the rapid corrosion of reboiler tubes at the depentanizers and debutanizers, where ammonia salts of organic sulfur acids dissociate to give acid conditions. The reboiler tube corrosion is aggravated by sludge carry-over by the water of ammonia-hydrogen sulfide corrosion products from elsewhere in the system. This sludge apparently provides a coalescing media for water and produces galvanic effects which further accelerate the corrosion.

By conducting the gas plant as above described with formaldehyde injection at strategic points wherever corrosion is experienced there is accomplished a considerable reduction if not complete elimination of loss by failure of parts and corrosion of metal surfaces.

We have found that in gas plants with certain flow conditions there exists a relationship between the amount of ammonia and water vapor present in the gas stream contacting heated metal surfaces and theamount of formaldehyde necessary to overcome the corrosion of the metal surfaces. For example, if the water content is reduced to zero, there is apparently no corrosion for no corrosive acid hydrolysis products are present. However, if the water content is 6.1 moles per hour or greater, then corrosion will be experienced even with a very small content of ammonia and hydrogen sulfide. To inhibit the corrosion of an atmosphere containing 6.1 moles of water per hour will require an amount of formaldehyde equivalent to the ammonia content. This reduces to a simple relationship in which the amount of formaldehyde injected must be at least as great as the balance of ammonia present. However, when treating gas streams in other types of processes, greater or lesser amounts of formaldehyde may be required.

In operating a gas plant processing ,as much as 20,000 cubic feet of gas per stream day it will be found that only small amounts, as for example, 1 to 5 liters of formaldehyde are necessary to reduce the corrosion appreciably. Larger amounts may be necessary if the operating conditions and character of the charge gas are conducive to extremely corrosive conditions. Reduction of the water content of the gases being charged to about 0.04 to 0.01 percent requires the injection of lesser amounts of formaldehyde. The exact amount of formaldehyde should be at least stoichiometrically equivalent to the amount of ammonia present remaining in the gases.

The invention has been described in connection with the corrosion problems experienced in a gas recovery plant. This, of course, represents only one embodiment of the invention since it is useful in any system which presents conditions of a comparable nature leading to corrosion. The equipment most concerned, namely, the reflux reboilers, condensers and coolers and the tubes therein, is constructed of carbon steel, stainless 9 steel, brasses, bronzes, Admiralty metal alloys, copper-nickel alloys and Monel metal alloys. However, the invention is applicable to other materials of construction such as other metal alloys, wrought iron, cast iron, ,magnet steel, Allegheny metal and Duriron.

The invention as herein set forth is embodied in particular form and manner but may be embodied in various other forms and manners still within the scope of the claims hereinafter made. Although in describing the invention, formaldehyde has been referred to specifically, other aldehydes, such as acetaldehyde, glyoxal, propionaldehyde, N-butyraldehyde, unsaturated aldehydes and aldehydes containing a heterocyclic nucleus, may be used provided the aldehyde is volatile under the conditions existing in the apparatus to be protected against corrosion. Paraformaldehyde or formalin solution may be used as a source of formaldehyde in accordance with the present invention. Before using the higher molecular weight aldehydes, it should be determined whether under the conditions present the neutral addition compound formed with ammonium sulfides, will be in the liquid or vapor state. It is undesirable to employ an aldehyde with a boiling point higher than furfural boiling at 162 C. since the neutral condensation product may be a solid and cause removal difiiculties.

This invention has been described in connection with corrosion problems resulting in processing overhead from cracking units by injection of formaldehyde at strategic points in the system. The invention is equally applicable in other embodiments, as for example, the combination of steps of dehydrating the overhead charge gas followed by the injection of formaldehyde therein. The process of this invention also applies to the prevention of corrosion during the stripping of sour crudes wherein ammonia is injected. It may also be applied to the prevention of corrosion in storage tanks containing sour crudes or pipe lines conveying same which now employ ammonia injection to overcome corrosion. In these latter processes the formaldehyde may be injected along with the ammonia neutralizer. So also, the hydrocarbon system containing corrosives may not contain ammonia, therefore ammonia may be injected into the hydrocarbon system followed by dehydration of the hydrocarbons with final aldehyde injection prior to contact with metal surfaces under conditions promoting corrosion.

The invention may be applied to any system in which the presence of ammonium sulfide causes corrosive effects which are more severe than either ammonia or hydrogen sulfide alone. If an attempt is made to neutralize the hydrogen sulfide of such systems in a conventional manner, as by treatment with caustic, there results a replacement reaction and free ammonia is produced which is very corrosive to brass equipment. In thermal cracking units ammonia is generally injected into the overhead vapor line leadin from the fractionating tower prior to entry into the condensers to neutralize the organic and inorganic acids present and thus reduce corrosion of the overhead vapor line, condensers and other equipment downstream from the cracking unit. lhe main corrosive in such units is the ammonium sulfide formed as a result of neutralization of the hydrogen sulfide with the ammonia injected. The injection of formaldehyde in accordance with this invention will greatly reduce the corrosion due to the presence of ammonium 10 sulfide in these thermal units and subsequent processing units.

The accompanying drawing is diagrammatic for purposes of simplicity and appropriate valves, regulators, and other detailed equipment has been omitted. A condenser is shown in the line leading to gas separator 3. In actual operation gas separator 5 should also be equipped with a condenser in its feed line or one condenser can serve both gas separators.

There are other embodiments of this invention which have not been described in this specification but which will obviously come within the definition of the invention as hereafter set forth in the claims.

What is claimed is:

1. The method of mitigating the corrosive effect of compounds of the group consisting of ammonium sulfide and ammonium hydrosulfide, in the presence of water, on ferrous and cupreous metal surfaces, comprising reacting such compounds with formaldehyde to form a neutral condensation product.

2, In the method of separating gasoline hydrocarbons from cracked overhead products from cracking units wherein atmospheres containing corrosive combinations of ammonia, hydrogen sulfide and water, are present, and cause excessive corrosion of ferrous and cupreous metal surfaces, the steps comprising dehydrating said cracked overhead products in a first stage, further dehydrating said overhead products in a second stage and injecting from about 0.01 to 3% of formaldehyde into said dehydrated overhead prior to contact with said ferrous and cupreous metal surfaces.

3. The method of inhibiting corrosion of equipment comprising a bi-metallic system consisting of ferrous and cupreous metals, said equipment being used to confine corrosive atmospheres consisting of stoichiometric amounts of ammonia in combination with sulfur compounds selected from the group consisting of hydrogen sulfide, mercaptans and disulfides, and water, which comprises adding to said atmospheres a corrosion inhibiting amount of a low molecular weight aldehyde.

4. The method of inhibiting the corrosive action of ammonium compounds selected from the group consisting of ammonium sulfide and ammonium hydrosulfide present in water-containing atmospheres, said compounds tending to form products having a corrosive effect on ferrous and cupreous metal surfaces, which comprises injecting a corrosion inhibiting amount of an aldehyde of low molecular weight into said atmospheres prior to contact with said metal surfaces.

5. A method in accordance with claim 4 in which the aldehyde is formaldehyde.

6. In the processing of petroleum hydrocarbons in which, concomitant with the processed petroleum hydrocarbons, is produced a corrosive environment consisting of ammonia, hydrogen sulfide and water, and in which said petroleum hydrocarbons in admixture with said corrosive environment are in contact with ferrous and cupreous metal surfaces, the step comprising injecting a corrosion inhibiting amount of a low molecular weight aldehyde into said petroleum hydrocarbon admixture in contact with said metallic surfaces to allay the corrosion thereof.

7. The method of inhibiting the corrosion of ferrous and cupreous metal surfaces of equipment used in gas recovery plants utilizing a feed stream of low molecular weight hydrocarbons containing in admixture therewith ammonia, hydrogen sulfide and water which comprises removing a substantial amount of the water from the feed stream charged to said plants and thereafter injecting a low molecular weight aldehyde into the feed stream prior to contacting the feed stream with said metal surfaces.

8. The method in accordance with claim 7 in which the low molecular weight aldehyde is formaldehyde.

9. The method in accordance with claim 8 in which the water content of the atmosphere is reduced to at least about 0.04 to 0.01 volume per- 12 cent and the amount of formaldehyde injected comprises approximately 0.001 to 0.004 volume percent of the atmosphere present.

CHRISTOPHER A. MURRAY.

REFERENCES CITED The following references are of record in the file of this patent:

UNITED STATES PATENTS Number Name Date 1,844,475 Morrell et a1. Feb. 9, 1932 2,415,161 Camp Feb. 4, 1947 

1. THE METHOD OF MITIGATING THE CORROSIVE EFFECT OF COMPOUNDS OF THE GROUP CONSISTING OF AMMONIUM SULFIDE AND AMMONIUM HYDROSULFIDE, IN THE PRESENCE OF WATER, ON FERROUS AND CUPREOUS METAL SURFACES, COMPRISING REACTING SUCH COMPOUNDS WITH FORMALDEHYDE TO FORM A NEUTRAL CONDENSATION PRODUCT. 